Dynamic gain system with azimuthal averaging for downhole logging tools

ABSTRACT

An example method may include transmitting a first acoustic signal from a downhole tool using a transmitter gain in a transmitter circuit. A first echo signal associated with the first acoustic signal may be received at the downhole tool using a receiver gain in a receiver circuit. At least one of the transmitter gain and the receiver gain may be adjusted based, at least in part, on the received first echo signal and at least one previously received echo signal.

CROSS-REFERENCE TO RELATED APPLICATION

The present application is a U.S. National Stage Application ofInternational Application No. PCT/US2016/029742 filed Apr. 28, 2016,which claims benefit of U.S. Provisional Application No. 62/165,641filed May 22, 2015, both of which are incorporated herein by referencein their entirety for all purposes.

The present disclosure relates generally to well drilling and completionoperations and, more particularly, to a dynamic gain system withazimuthal averaging for downhole logging tools.

Hydrocarbons, such as oil and gas, are commonly obtained fromsubterranean formations that may be located onshore or offshore. Thedevelopment of subterranean operations and the processes involved inremoving hydrocarbons from a subterranean formation are complex.Typically, subterranean operations involve a number of different stepssuch as, for example, drilling a wellbore at a desired well site,treating the wellbore to optimize production of hydrocarbons, andperforming the necessary steps to produce and process the hydrocarbonsfrom the subterranean formation. Well drilling and completion operationsrequire information on downhole characteristics to aide in decisionmaking processes. That information may be provided by measurement andlogging tools positioned within the wellbore. Typical acoustic loggingtools operate by sending an acoustic pulse into the wellbore andreceiving an echo after the acoustic pulse is reflected by casing orpipe in the cased-hole application and by the wellbore wall in theopen-hole application. The waveform of the echo can then be used tocalculated or otherwise deduce physical properties of the casing/pipe orborehole wall (such as the impedance, thickness, slowness, reflectanceetc.).

The transmitted acoustic pulses may be subject to attenuation that is afunction of the operating condition of the acoustic logging tools(casing thickness, mud weight, borehole size, borehole wall rugosity,etc.). If the pulse is attenuated too much, the echo signal may haveinsufficient amplitude to provide reliable signal quality. If the pulseis not attenuated enough, the echo signal may saturate the receiver,which also leads to poor signal quality. Because the operatingconditions may change over time, maintaining proper gain adjustments inthe tool may be important to ensuring sufficient signal quality andaccurate calculations regarding the physical properties.

FIGURES

Some specific exemplary embodiments of the disclosure may be understoodby referring, in part, to the following description and the accompanyingdrawings.

FIG. 1 is a diagram illustrating an example acoustic logging tool,according to aspects of the present disclosure.

FIG. 2 is a block diagram of an example firing system for an acousticlogging tool, according to aspects of the present disclosure.

FIG. 3 is an example process for altering the gain at the receiver,according to aspects of the present disclosure.

FIG. 4 is an example process for altering the gain at the receiver,according to aspects of the present disclosure.

FIG. 5 is a diagram showing an illustrative drilling system, accordingto aspects of the present disclosure.

FIG. 6 is a diagram showing an illustrative wireline logging system,according to aspects of the present disclosure.

While embodiments of this disclosure have been depicted and describedand are defined by reference to exemplary embodiments of the disclosure,such references do not imply a limitation on the disclosure, and no suchlimitation is to be inferred. The subject matter disclosed is capable ofconsiderable modification, alteration, and equivalents in form andfunction, as will occur to those skilled in the pertinent art and havingthe benefit of this disclosure. The depicted and described embodimentsof this disclosure are examples only, and not exhaustive of the scope ofthe disclosure.

DETAILED DESCRIPTION

The present disclosure relates generally to well drilling and completionoperations and, more particularly, to a dynamic gain system withazimuthal averaging for downhole logging tools.

For purposes of this disclosure, an information handling system mayinclude any instrumentality or aggregate of instrumentalities operableto compute, classify, process, transmit, receive, retrieve, originate,switch, store, display, manifest, detect, record, reproduce, handle, orutilize any form of information, intelligence, or data for business,scientific, control, or other purposes. For example, an informationhandling system may be a personal computer, a network storage device, orany other suitable device and may vary in size, shape, performance,functionality, and price. The information handling system may includerandom access memory (RAM), one or more processing resources such as acentral processing unit (CPU) or hardware or software control logic,ROM, and/or other types of nonvolatile memory. Additional components ofthe information handling system may include one or more disk drives, oneor more network ports for communication with external devices as well asvarious input and output (I/O) devices, such as a keyboard, a mouse, anda video display. The information handling system may also include one ormore buses operable to transmit communications between the varioushardware components. It may also include one or more interface unitscapable of transmitting one or more signals to a controller, actuator,or like device.

For the purposes of this disclosure, computer-readable media may includeany instrumentality or aggregation of instrumentalities that may retaindata and/or instructions for a period of time. Computer-readable mediamay include, for example, without limitation, storage media such as adirect access storage device (e.g., a hard disk drive or floppy diskdrive), a sequential access storage device (e.g., a tape disk drive),compact disk, CD-ROM, DVD, RAM, ROM, electrically erasable programmableread-only memory (EEPROM), and/or flash memory; as well ascommunications media such wires, optical fibers, microwaves, radiowaves, and other electromagnetic and/or optical carriers; and/or anycombination of the foregoing.

Illustrative embodiments of the present disclosure are described indetail herein. In the interest of clarity, not all features of an actualimplementation may be described in this specification. It will of coursebe appreciated that in the development of any such actual embodiment,numerous implementation specific decisions are made to achieve thespecific implementation goals, which will vary from one implementationto another. Moreover, it will be appreciated that such a developmenteffort might be complex and time-consuming, but would nevertheless be aroutine undertaking for those of ordinary skill in the art having thebenefit of the present disclosure.

To facilitate a better understanding of the present disclosure, thefollowing examples of certain embodiments are given. In no way shouldthe following examples be read to limit, or define, the scope of thedisclosure. Embodiments of the present disclosure may be applicable tohorizontal, vertical, deviated, or otherwise nonlinear wellbores in anytype of subterranean formation. Embodiments may be applicable toinjection wells as well as production wells, including hydrocarbonwells. Embodiments may be implemented using a tool that is made suitablefor testing, retrieval and sampling along sections of the formation.Embodiments may be implemented with tools that, for example, may beconveyed through a flow passage in tubular string or using a wireline,slickline, coiled tubing, downhole robot/tractor or the like.

The terms “couple” or “couples” as used herein are intended to meaneither an indirect or a direct connection. Thus, if a first devicecouples to a second device, that connection may be through a directconnection or through an indirect mechanical or electrical connectionvia other devices and connections. Similarly, the term “communicativelycoupled” as used herein is intended to mean either a direct or anindirect communication connection. Such connection may be a wired orwireless connection such as, for example, Ethernet or LAN. Such wiredand wireless connections are well known to those of ordinary skill inthe art and will therefore not be discussed in detail herein. Thus, if afirst device communicatively couples to a second device, that connectionmay be through a direct connection, or through an indirect communicationconnection via other devices and connections.

Modern petroleum drilling and production operations demand informationrelating to parameters and conditions downhole. Several methods existfor downhole information collection, including logging-while-drilling(“LWD”) and measurement-while-drilling (“MWD”), and wireline. In LWD,data is typically collected during the drilling process, therebyavoiding any need to remove the drilling assembly to insert a wirelinelogging tool. LWD consequently allows the driller to make accuratereal-time modifications or corrections to optimize performance whileminimizing down time. MWD is the term for measuring conditions downholeconcerning the movement and location of the drilling assembly while thedrilling continues. LWD concentrates more on formation parametermeasurement. While distinctions between MWD and LWD may exist, the termsMWD and LWD often are used interchangeably. For the purposes of thisdisclosure, the term LWD will be used with the understanding that thisterm encompasses both the collection of formation parameters and thecollection of information relating to the movement and position of thedrilling assembly.

FIG. 1 is a diagram illustrating an example acoustic logging tool 100,according to aspects of the present disclosure. The tool 100 may besuspended (e.g. via wireline, slickline, coiled tubing, drillpipe/tubing, downhole tractor, or the like) within a wellbore 150 in asubterranean formation 152. As depicted, the tool 100 may be positionedwithin a casing 102 that is secured in the wellbore 150 by a cementlayer 104 that substantially fills the annulus between the casing 102and the wellbore 150. The casing 102 may comprise a metal tubular with apre-determined length and diameter that is specifically selected for aparticular depth in the formation 152. Although only one casing 102 isshown in FIG. 1, multiple casings may be used, including in a telescopicorientation where casings with progressively smaller diameters arc usedas the wellbore 150 extends further into the formation 152. The casing112 may prevent the wellbore 150 from collapsing, prevent sensitiveformation strata from exposure to downhole fluids, and prevent unwantedformation fluids from entering the wellbore 150. This embodiment isreferred to a “cased” hole. The tool may also be positioned within an“open” hole, which may comprise the wellbore 150 without the casing 102or the cement layer 104.

The tool 100 comprises an elongated tool body 120 comprising a rotatingportion 108 with a single acoustic transducer 106 coupled thereto.Example acoustic transducers include, but are not limited to,piezoelectric crystals, geophones, electromagnetic elements, etc. Asdepicted, the rotating portion 108 comprises a rotating head positionedat a distal end of the elongated tool body 120. In other embodiments,the rotation portion 108 may be positioned at one or more intermediateportions of the elongated tool body 120, which may provide greaterflexibility with respect to the tool design. As depicted, the diameterof the rotating portion 108 is larger than the diameter of the elongatedtool body 120, but other configurations are possible within the scope ofthe present disclosure.

The rotating portion 108 may be driven by an electric motor (not shown)or another suitable drive mechanism that provides for the controlledrotational movement of the rotating portion 108 with respect to the tool100. As depicted, the rotating portions 108 may be driven through ashaft connecting the rotating portion 108 to a drive mechanism withinthe elongated tool body 120. Power for the drive mechanism and otherelements within the tool 100 may be provided, for instance, through themeans of suspension, or by one or more power sources, e.g., batteries,capacitors, generators, within the tool 100.

In use, the transducer 106 may transmit a directional acoustic pulse 110to the casing 102 at a first azimuthal location with respect to the tool100. The directional acoustic pulse 110 may be characterized by a peakamplitude. The directional acoustic pulse 110 is not limited withrespect to frequency and can but is not required to be an ultrasonicpulse. The pulse 110 may contact, be reflected by, and/or cause toreverberate the casing 102, the cement layer 104, and the interfacebetween the casing 102 and the cement layer 104. These reflections andreverberations may comprise an echo signal 112 that is received by thetransducer 106. The echo signal 112 also may be characterized by a peakamplitude, with the difference between the peak amplitude of the echosignal 112 and the peak amplitude of the directional acoustic pulse 110corresponding to an attenuation of the directional acoustic pulse 110.In certain instances, one or more pulses may also contact, be reflectedby, and/or cause to reverberate the formation 152 and the interfacebetween the cement layer 104 and the formation 152.

After the echo signal 112 is received from the first azimuthal location,the head 108 may be rotated to a second azimuthal location within thewellbore 150. Another pulse may then be transmitted from the transducer106, and a corresponding echo signal may be received at the transducer106. The head 108 then may be rotated to a third azimuthal locationwithin the wellbore 150 and yet another pulse may then be transmittedfrom the transducer 106, and a corresponding echo signal may be receivedat the transducer 106. The first, second and third azimuthal locationsmay but are not required to be equal rotational intervals with respectto the tool 100. For instance, the angular difference between theazimuthal locations may be modified in real time depending on thesignals received and the granularity of the resulting measurements, withsmaller rotational intervals corresponding to a higher granularity.

In certain embodiments, this process may continue until the head 108 hascompleted a rotation, at which point the tool 300 may be positioned at adifferent depth. The group of azimuthal measurements taken at aparticular depth may be referred to as a “scan.” The number of azimuthalmeasurements taken to complete a scan may depend, for instance, on thegranularity required by the combined measurements as well as downholeconditions. Although not shown, instead of a rotating head, the wholetool 100 or a portion thereof having the transducer 106 can be rotatedto accomplish a similar azimuthal scan. For example, if the tool 100 isconveyed into the wellbore 150 via drill pipe, the drill pipe could berotated to in-turn rotate the tool 100 and thereby the transducer 106.

In certain embodiments, each echo signal received by the transducer 106may be transmitted to one or more control systems (not shown) associatedwith the tool 100, where it can be processed, for example, for thepurposes of controlling or altering the configuration of the tool 100 orelements of the tool 100, or for the purpose of determining physicalcharacteristics (e.g., impedance, thickness, slowness, reflectance) ofthe casing 102 and cement layer 104. As used herein a control system maycomprise an information handling system or any other device thatcontains at least one processor communicably coupled to a non-transitorycomputer readable memory device containing a set of instructions thatwhen executed by the processor, cause it to perform certain actions.Example processors include microprocessors, microcontrollers, digitalsignal processors (DSP), application specific integrated circuits(ASIC), or any other digital or analog circuitry configured to interpretand/or execute program instructions and/or process data. The one or morecontrol systems associated with the tool 100 could be, for example,wholly within the tool 100, located at the surface, or a combination ofthe two (e.g. some processing occurring downhole and some done at thesurface.

Attenuation conditions with the wellbore 150 may affect the signalquality of the echo signal. Those conditions may be a function of theoperating condition of the tools. For instance, the thickness of thecasing 102, the size and shape of the borehole within the formation 152,the fluid characteristics of drilling mud or other fluids within thecasing 102, etc. can all affect the peak amplitude of the echo 112. Ifthe pulse 110 is attenuated too much, the echo signal 112 may haveinsufficient amplitude to provide reliable signal quality. In contrast,if the pulse 110 is not attenuated enough, the echo signal 112 maysaturate the receiver, which also leads to poor signal quantity.Notably, the attenuation conditions may change with respect to azimuthalpositions around the tool 100 and also with respect to the depth atwhich the tool 100 is positioned within the wellbore 152.

According to aspects of the present disclosure, gain adjustments withrespect to both the transmitted acoustic pulse 110 and the received echosignal 112 may be made to adjust for dynamic attenuation conditions andimprove the resulting measurements. These gain adjustments can, but arenot required to, be made in a control system of the tool 110, which maycomprise a firing system responsible for the transmission and receptionof signals with respect to the tool 100. FIG. 2 is a block diagram of anexample firing system 200 for an acoustic logging tool, according toaspects of the present disclosure. The system 200 comprises a firingcontroller 202 coupled to transmitter circuitry 204 and receivercircuitry 206, both of which are coupled to a transducer 250. The firingcontroller 202 may comprise a control unit located within the loggingtool, at the surface, or a combination of the two. The transducer 250may comprise a transceiver or an independent transmitter and anindependent receiver.

As depicted, the transmitter circuitry 204 comprises a transmitter 208with pulse generator circuitry and a programmable voltage supply, thatoutputs voltage pulses to the transducer 250 to cause it to generatedesired acoustic pulses with peak amplitudes that corresponds to thepeak amplitudes of the voltage pulses. The transmitter circuitry 204further includes a power supply 210 that may receive one or more controlsignals from the firing controller 202 that cause it to alter the powersupplied to the transmitter 208. In particular, a digital-to-analogconverter (DAC) 212 of the power supply 210 may receive the controlsignal from the firing controller 202 over a dedicated communicationchannel 214, such as a Inter Integrated Circuit Communications (I2C)channel or a Serial-Peripheral Interface (SPI). The control signalreceived at the power supply 210 from the firing controller 202 maycomprise a gain adjustment signal that causes the amplitude of thevoltage pulses and therefore the amplitude of the acoustic pulsesgenerated by the transducer 250 to change. Other configurations arepossible within the scope of this disclosure.

As depicted, the receiver circuitry 206 comprises a DAC 216, aprogrammable gain amplifier 218, and a signal conditioning block 220.Like the DAC 212 of the transmitter circuitry 204, the DAC 216 of thereceiver circuitry 206 may receive gain adjustment signals from thefiring controller 202 over a dedicated I2C/SPI channel 222. In responseto the gain adjustment signal, the DAC 216 may output a signal to theprogrammable amplifier 218 that alters the gain applied to an echosignal received through the transducer 250, effectively changing thepeak amplitude of the each signal received at the tool. The signalconditioning block 220 may filter the amplified echo signal beforetransmitting the echo signal to the firing controller 202. Otherconfigurations are possible within the scope of this disclosure.

In one or more embodiments, the firing controller 202 comprises a dataacquisition (DAQ) system 224 that manages both data acquisition andprocessing functionalities to control the gain within the firing system200. In particular, during data acquisition, an analog-to-digitalconverter (ADC) 226 may receive an echo signal and sample the signal.This may act to update the receiver gain adjustment for the current echosignal acquisition. After the sampled data is acquired, a digital signalprocessor (DSP) 228 of the DAQ 224 may calculate the echo arrival timeand peak amplitude level with respect to the transmitted pulses. Thisinformation may then be used to adjust generate gain adjustment signalsfor at least one of the transmitter circuitry 204 and the receivercircuitry 206.

In one or more embodiments, the gain adjustment signals may be based, atleast in part, on the following gain adjustment equation:

${G_{r}(n)} = \left\{ \begin{matrix}{{G_{r}\left( {n - 1} \right)},{{0.9A_{opt}} < {G_{r}\left( {n - 1} \right)} < {1.1A_{opt}}}} \\{{{G_{r}\left( {n - 1} \right)} + {\mu_{r}{\log\left( \frac{A_{opt}}{\sum\limits_{k = 1}^{M}{\alpha_{r}\left( {n - k} \right)}} \right)}}},{otherwise}}\end{matrix} \right.$

where G_(r)(n) corresponds to the receiver gain for the n-thacquisition, A_(opt) corresponds to the optimal ADC level, α_(r)(n)corresponds to the echo amplitude calculated for the n-th acquisition; Mcorresponds to a predetermined number of previous echo signalacquisitions; and μ_(r) comprises a constant step size that defines aconvergence rate of the adjustment. Accordingly, the gain adjustmentsignal may account for at least one previously captured echo signal atthe tool. By accounting for a range of acquired echo signals, the firingsystem 200 may maximize the dynamic range of the ADC when sampling theecho signal, neglect minor change in the receiver gain within the sameazimuth acquisition, detect and prevent saturation at the ADC thatresults in loss of data, and protect against intermittent acquisitionerrors.

FIG. 3 is an example process for altering the gain at the receiver,according to aspects of the present disclosure. In one or moreembodiments, the process described with respect to FIG. 3 may beimplemented in the DSP of the tool described above with respect to FIG.2, or in any other suitable control system. Step 301 comprises settingthe receiver gain at a first value, which may be based, for example on ainitialization value or some experimentally acquired value. Step 302comprises acquiring an individual “shot” which may include transmittingan acoustic pulse from a transducer and receiving a corresponding echosignal, as described above. Step 303 comprises determining a peakamplitude of the received echo signal. Step 304 comprises storing thepeak amplitude in a data buffer 305. Step 301-304 may be repeated untilthe buffer 305 is full or has reached a minimum capacity M necessary toperform to use a gain adjustment equation similar to the one describedabove.

At step 306, once the buffer 305 is full or has reached a minimumcapacity M, the average peak over the previous M shots may bedetermined. At step 307, once the average peak value is determined, thevalue may be used in a gain adjustment equation, for example, to adjustthe gain at the receiver circuitry prior to the next shot. For eachsubsequent shot, the oldest stored value within the buffer 305 may bepushed out and the average peak value recalculated. Accordingly, thegain may be adjusted after each shot based on a running window ofresults for the previous M shots. Notably, the value of M may beadjusted based on the operating conditions of the logging tool,including the potential shot-to-shot variability.

FIG. 4 is an example process for altering the gain at the transmitter,according to aspects of the present disclosure. Like the processdescribed with respect to FIG. 3, the process described with respect toFIG. 4 also may be implemented in the DSP of the tool described abovewith respect to FIG. 2, or in any other suitable control system. At step401, the transmitter gain may be set at a first value. At step 402, afirst scan may be completed. As described above, a scan may comprise aseries of azimuthal shots at a particular depth. After the scan iscompleted, the gain information for the scan may be stored at step 403within the buffer 404. The gain information may include, for example,average gain information with respect to all shots taken during thatscan. Steps 401-403 may be repeated with subsequent scans until thebuffer contains at least M entries, which may correspond to theaveraging window of a corresponding gain adjustment equation. At step405, once the buffer contains at least M entries, the gain informationfor M entries in the buffer 403 may be retrieved and an average gainfigure may be calculated. Based, at least in part, on that average gaininformation and a gain adjustment algorithm, the gain at the transmittermay be updated for the transmitter at step 406. For each subsequentscan, the oldest stored value within the buffer 404 may be pushed outand the average peak value recalculated. Accordingly, the gain may beadjusted after each scan based on a running window of results for theprevious M scans. Notably, the value of M may be adjusted based on theoperating conditions of the logging tool, including the potentialshot-to-shot variability.

Although the gain for both the transmitter and receiver circuity can beadjusted between every shot, it is preferred that the transmittercircuitry gain be adjusted only between scans rather than betweenindividual shots. This is because adjusting the transmitter circuitrygain within a scan may skew the resulting echo signals such thatcharacteristics at the scan depth can no longer be accuratelydetermined.

One or more of the apparatus, systems, and/or methods described abovemay be incorporated into/with a wireline tool/sonde for wireline loggingoperation or into/with one or more LWD/MWD tools for drillingoperations. FIG. 5 is a diagram showing a subterranean drilling system80 incorporating at least one acoustic LWD/MWD tool 26, according toaspects of the present disclosure. The drilling system 80 comprises adrilling platform 2 positioned at the surface 82. As depicted, thesurface 82 comprises the top of a formation 84 containing one or morerock strata or layers 18 a-c, and the drilling platform 2 may be incontact with the surface 82. In other embodiments, such as in anoff-shore drilling operation, the surface 82 may be separated from thedrilling platform 2 by a volume of water.

The drilling system 80 comprises a derrick 4 supported by the drillingplatform 2 and having a traveling block 6 for raising and lowering adrill string 8. A kelly 10 may support the drill string 8 as it islowered through a rotary table 12. A drill bit 14 may be coupled to thedrill string 8 and driven by a downhole motor and/or rotation of thedrill string 8 by the rotary table 12. As bit 14 rotates, it creates aborehole 16 that passes through one or more rock strata or layers 18. Apump 20 may circulate drilling fluid through a feed pipe 22 to kelly 10,downhole through the interior of drill string 8, through orifices indrill bit 14, back to the surface via the annulus around drill string 8,and into a retention pit 24. The drilling fluid transports cuttings fromthe borehole 16 into the pit 24 and aids in maintaining integrity or theborehole 16.

The drilling system 80 may comprise a bottom hole assembly (BHA) coupledto the drill string 8 near the drill bit 14. The BHA may comprisevarious downhole measurement tools and sensors and LWD and MWD elements,including the acoustic tool 26. In one or more embodiments, the tool 26may comprise acoustic pulse excitation and echo/reflection receptionfunctionality that will be described in detail below. As the bit extendsthe borehole 16 through the formations 18, the tool 26 may collectmeasurements relating to borehole 16 and the formation 84. In certainembodiments, the orientation and position of the acoustic tool 26 may betracked using, for example, an azimuthal orientation indicator, whichmay include magnetometers, inclinometers, and/or accelerometers, thoughother sensor types such as gyroscopes may be used in some embodiments.

The tools and sensors of the BHA including the tool 26 may becommunicably coupled to a telemetry element 28. The telemetry element 28may transfer measurements from acoustic tool 26 to a surface receiver 30and/or to receive commands from the surface receiver 30. The telemetryelement 28 may comprise a mud pulse telemetry system, and acoustictelemetry system, a wired communications system, a wirelesscommunications system, or any other type of communications system thatwould be appreciated by one of ordinary skill in the art in view of thisdisclosure. In certain embodiments, some or all of the measurementstaken at the tool 26 may also be stored within the tool 26 or thetelemetry element 28 for later retrieval at the surface 82.

In certain embodiments, the drilling system 80 may comprise a surfacecontrol unit 32 positioned at the surface 102. The surface control unit32 may comprise an information handling system communicably coupled tothe surface receiver 30 and may receive measurements from the acoustictool 26 and/or transmit commands to the acoustic tool 26 though thesurface receiver 30. The surface control unit 32 may also receivemeasurements from the acoustic tool 26 when the acoustic tool 26 isretrieved at the surface 102. As is described above, the surface controlunit 32 may process some or all of the measurements from the acoustictool 26 to determine certain parameters of downhole elements, includingthe borehole 16 and formation 84.

At various times during the drilling process, the drill string 8 may beremoved from the borehole 16 as shown in FIG. 6. Once the drill string 8has been removed, measurement/logging operations can be conducted usinga wireline tool 34, e.g., an instrument that is suspended into theborehole 16 by a cable 15 having conductors for transporting power tothe tool and telemetry from the tool body to the surface 102. Thewireline tool 34 may comprise an acoustic tool 36, similar to theacoustic tool 26 described above. The tool 36 may be communicativelycoupled to the cable 15. A logging facility 44 (shown in FIG. 5 as atruck, although it may be any other structure) may collect measurementsfrom the acoustic tool 36, and may include computing facilities(including, e.g., a control unit/information handling system) forcontrolling, processing, storing, and/or visualizing some or all of themeasurements gathered by the tool 36. The computing facilities may becommunicatively coupled to the acoustic tool 36 by way of the cable 15.In certain embodiments, the control unit 32 may serve as the computingfacilities of the logging facility 44.

An example method may include transmitting a first acoustic signal froma downhole tool using a transmitter gain in a transmitter circuit. Afirst echo signal associated with the first acoustic signal may bereceived at the downhole tool using a receiver gain in a receivercircuit. At least one of the transmitter gain and the receiver gain maybe adjusted based, at least in part, on the received first echo signaland at least one previously received echo signal.

In one or more embodiments described in the preceding paragraph,transmitting the first acoustic signal from the downhole tool using thefirst transmitter gain in the transmitter circuit comprises transmittingthe first acoustic signal from a transducer coupled to the transmittercircuit.

In one or more embodiments described in the preceding two paragraphs,receiving the echo signal associated with the first acoustic signalusing the first receiver gain in the receiver circuit comprisesreceiving the echo signal from the transducer, wherein the transducer iscoupled to the receiver circuit.

In one or more embodiments described in the preceding three paragraphs,the transducer is coupled to a rotating portion of the downhole tool.

In one or more embodiments described in the preceding four paragraphs,the rotating portion comprises a rotating head positioned at a distalend of the downhole tool.

In one or more embodiments described in the preceding five paragraphs, asecond acoustic signal may be transmitted from the downhole tool and asecond echo signal associated with the second acoustic signal may bereceived at the tool using at least one of the adjusted transmitter gainand the adjusted receiver gain.

In one or more embodiments described in the preceding six paragraphs,transmitting the second acoustic signal from the downhole tool comprisestransmitting the second acoustic signal at the same depth but adifferent azimuthal orientation that the first acoustic signal; andreceiving at the downhole tool the second echo signal comprisesreceiving the second echo signal using the adjusted receiver gain.

In one or more embodiments described in the preceding seven paragraphs,transmitting the second acoustic signal from the downhole tool comprisestransmitting the second acoustic signal at a different depth but adifferent azimuthal orientation that the first acoustic signal using theadjusted transmitter gain.

In one or more embodiments described in the preceding eight paragraphs,adjusting the receiver gain based, at least in part, on the receivedfirst echo signal and at least one previously received echo signalcomprises adjusting the receiver gain using the following equation

${G_{r}(n)} = \left\{ \begin{matrix}{{G_{r}\left( {n - 1} \right)},{{0.9A_{opt}} < {G_{r}\left( {n - 1} \right)} < {1.1A_{opt}}}} \\{{{G_{r}\left( {n - 1} \right)} + {\mu_{r}{\log\left( \frac{A_{opt}}{\sum\limits_{k = 1}^{M}{\alpha_{r}\left( {n - k} \right)}} \right)}}},{otherwise}}\end{matrix} \right.$where G_(r)(n) corresponds to a receiver gain associated with an n-thpreviously received echo signal, A_(opt) corresponds to an optimal levelassociated with an analog-to-digital converter of the tool, α_(r)(n)corresponds to an echo amplitude calculated for the n-th previouslyreceived echo signal; M corresponds to a predetermined number ofprevious received echo signals; μ_(r) comprises a constant step sizethat defines a convergence rate of an adjustment.

In one or more embodiments described in the preceding nine paragraphs, Mdepends, at least in part, on one or more downhole conditions associatedwith the downhole tool.

An example system may include a downhole tool and a transducer coupledto the downhole tool. A transmitted circuit may be coupled to thetransducer and characterized by a transmitter gain. A receiver circuitmay be coupled to the transducer and characterized by a receiver gain. Acontroller may be communicably coupled to the transmitter circuit andthe receiver circuit and configured to cause the transmitter circuit totransmit a first acoustic signal from the transducer using thetransmitter gain; cause the receiver circuit to receive from thetransducer a first echo signal associated with the first acoustic signalusing the receiver gain; and adjust at least one of the transmitter gainand the receiver gain based, at least in part, on the received firstecho signal and at least one previously received echo signal.

In one or more embodiments described in the preceding paragraph, thedownhole tool comprises a rotating portion to which the transducer iscoupled.

In one or more embodiments described in the preceding two paragraphs,the rotating portion comprises a rotating head positioned at a distalend of the downhole tool.

In one or more embodiments described in the preceding three paragraphs,the transducer comprises at least one of a piezoelectric element, ageophone, and an electromagnetic element.

In one or more embodiments described in the preceding four paragraphs,the downhole tool comprises one of a wireline tool and alogging-while-drilling tool.

In one or more embodiments described in the preceding five paragraphs,the controller is further configured to cause the transmitter circuit totransmit a second acoustic signal and the receiver circuit to receive asecond echo signal associated with the second acoustic signal using atleast one of the adjusted transmitter gain and the adjusted receivergain.

In one or more embodiments described in the preceding six paragraphs thedownhole tool comprises a rotating portion to which the transducer iscoupled; and the controller is further configured to cause rotatingportion of the downhole tool to alter the azimuthal orientation of thetransducer before the second acoustic signal is transmitted; and causethe receiver circuit to receive the second echo signal using theadjusted receiver gain.

In one or more embodiments described in the preceding seven paragraphs,the controller is further configured to adjust the transmitter gainbetween depth changes of the downhole tool in a borehole.

In one or more embodiments described in the preceding eight paragraphs,the controller is further configured to adjust the receiver gain usingthe following equation

${G_{r}(n)} = \left\{ \begin{matrix}{{G_{r}\left( {n - 1} \right)},{{0.9A_{opt}} < {G_{r}\left( {n - 1} \right)} < {1.1A_{opt}}}} \\{{{G_{r}\left( {n - 1} \right)} + {\mu_{r}{\log\left( \frac{A_{opt}}{\sum\limits_{k = 1}^{M}{\alpha_{r}\left( {n - k} \right)}} \right)}}},{otherwise}}\end{matrix} \right.$where G_(r)(n) corresponds to a receiver gain associated with an n-thpreviously received echo signal, A_(opt) corresponds to an optimal levelassociated with an analog-to-digital converter of the tool, α_(r)(n)corresponds to an echo amplitude calculated for the n-th previouslyreceived echo signal; M corresponds to a predetermined number ofprevious received echo signals; and μ_(r) comprises a constant step sizethat defines a convergence rate of an adjustment.

In one or more embodiments described in the preceding nine paragraphs, Mdepends, at least in part, on one or more downhole conditions associatedwith the downhole tool.

Therefore, the present disclosure is well adapted to attain the ends andadvantages mentioned as well as those that are inherent therein. Theparticular embodiments disclosed above are illustrative only, as thepresent disclosure may be modified and practiced in different butequivalent manners apparent to those skilled in the art having thebenefit of the teachings herein. Furthermore, no limitations arcintended to the details of construction or design herein shown, otherthan as described in the claims below. It is therefore evident that theparticular illustrative embodiments disclosed above may be altered ormodified and all such variations are considered within the scope andspirit of the present disclosure. Also, the terms in the claims havetheir plain, ordinary meaning unless otherwise explicitly and clearlydefined by the patentee. The indefinite articles “a” or “an,” as used inthe claims, are defined herein to mean one or more than one of theelement that it introduces.

What is claimed is:
 1. A method, comprising: transmitting a firstacoustic signal from a downhole tool using a transmitter gain in atransmitter circuit; receiving at the downhole tool a first echo signalassociated with the first acoustic signal using a receiver gain in areceiver circuit; adjusting the transmitter gain, at least in part, onthe received first echo signal and at least one previously received echosignal; and adjusting the receiver gain based, at least in part, on anoptimal level associated with an analog-to-digital convertor of thetool.
 2. The method of claim 1, wherein transmitting the first acousticsignal from the downhole tool using the first transmitter gain in thetransmitter circuit comprises transmitting the first acoustic signalfrom a transducer coupled to the transmitter circuit.
 3. The method ofclaim 2, wherein receiving the echo signal associated with the firstacoustic signal using the first receiver gain in the receiver circuitcomprises receiving the echo signal from the transducer, wherein thetransducer is coupled to the receiver circuit.
 4. The method of claim 2,wherein the transducer is coupled to a rotating portion of the downholetool.
 5. The method of claim 4, wherein the rotating portion comprises arotating head positioned at a distal end of the downhole tool.
 6. Themethod of claim 1, further comprising transmitting a second acousticsignal from the downhole tool and receiving at the downhole tool asecond echo signal associated with the second acoustic signal using atleast one of the adjusted transmitter gain and the adjusted receivergain.
 7. The method of claim 6, wherein transmitting the second acousticsignal from the downhole tool comprises transmitting the second acousticsignal at the same depth but a different azimuthal orientation than thatof the first acoustic signal; and receiving at the downhole tool thesecond echo signal comprises receiving the second echo signal using theadjusted receiver gain.
 8. The method of claim 6, wherein transmittingthe second acoustic signal from the downhole tool comprises transmittingthe second acoustic signal at a different depth but a differentazimuthal orientation that the first acoustic signal using the adjustedtransmitter gain.
 9. The method of claim 1, wherein adjusting thereceiver gain comprises using the following equation${G_{r}(n)} = \left\{ \begin{matrix}{{G_{r}\left( {n - 1} \right)},{{0.9A_{opt}} < {G_{r}\left( {n - 1} \right)} < {1.1A_{opt}}}} \\{{{G_{r}\left( {n - 1} \right)} + {\mu_{r}{\log\left( \frac{A_{opt}}{\sum\limits_{k = 1}^{M}{\alpha_{r}\left( {n - k} \right)}} \right)}}},{otherwise}}\end{matrix} \right.$ where G_(r)(n) corresponds to a receiver gainassociated with an n-th previously received echo signal, A_(opt)corresponds to an optimal level associated with an analog-to-digitalconverter of the tool, α_(r)(n) corresponds to an echo amplitudecalculated for the n-th previously received echo signal; M correspondsto a predetermined number of previous received echo signals; μ_(r)comprises a constant step size that defines a convergence rate of anadjustment.
 10. The method of claim 9, wherein M depends, at least inpart, on one or more downhole conditions associated with the downholetool.
 11. A system, comprising a downhole tool; a transducer coupled tothe downhole tool; a transmitter circuit coupled to the transducer andcharacterized by a transmitter gain; a receiver circuit coupled to thetransducer and characterized by a receiver gain; and a controllercommunicably coupled to the transmitter circuit and the receiver circuitand configured to cause the transmitter circuit to transmit a firstacoustic signal from the transducer using the transmitter gain; causethe receiver circuit to receive from the transducer a first echo signalassociated with the first acoustic signal using the receiver gain; andadjust the transmitter gain, at least in part, on the received firstecho signal and at least one previously received echo signal; and adjustthe receiver gain based, at least in part, on an optimal levelassociated with an analog-to-digital convertor of the tool.
 12. Thesystem of claim 11, wherein the downhole tool comprises a rotatingportion to which the transducer is coupled.
 13. The system of claim 12,wherein the rotating portion comprises a rotating head positioned at adistal end of the downhole tool.
 14. The system of claim 11, wherein thetransducer comprises at least one of a piezoelectric element, ageophone, and an electromagnetic element.
 15. The system of claim 11,wherein the downhole tool comprises one of a wireline tool and alogging-while-drilling tool.
 16. The system of claim 11, wherein thecontroller is further configured to cause the transmitter circuit totransmit a second acoustic signal and the receiver circuit to receive asecond echo signal associated with the second acoustic signal using atleast one of the adjusted transmitter gain and the adjusted receivergain.
 17. The system of claim 16, wherein the downhole tool comprises arotating portion to which the transducer is coupled; and the controlleris further configured to cause rotating portion of the downhole tool toalter the azimuthal orientation of the transducer before the secondacoustic signal is transmitted; and cause the receiver circuit toreceive the second echo signal using the adjusted receiver gain.
 18. Thesystem of claim 11, wherein the controller is further configured toadjust the transmitter gain between depth changes of the downhole toolin a borehole.
 19. The system of claim 11, wherein the controller isfurther configured to adjust the receiver gain using the followingequation ${G_{r}(n)} = \left\{ \begin{matrix}{{G_{r}\left( {n - 1} \right)},{{0.9A_{opt}} < {G_{r}\left( {n - 1} \right)} < {1.1A_{opt}}}} \\{{{G_{r}\left( {n - 1} \right)} + {\mu_{r}{\log\left( \frac{A_{opt}}{\sum\limits_{k = 1}^{M}{\alpha_{r}\left( {n - k} \right)}} \right)}}},{otherwise}}\end{matrix} \right.$ where G_(r)(n) corresponds to a receiver gainassociated with an n-th previously received echo signal, A_(opt)corresponds to an optimal level associated with an analog-to-digitalconverter of the tool, α_(r)(n) corresponds to an echo amplitudecalculated for the n-th previously received echo signal; M correspondsto a predetermined number of previous received echo signals; and μ_(r)comprises a constant step size that defines a convergence rate of anadjustment.
 20. The system of claim 19, wherein M depends, at least inpart, on one or more downhole conditions associated with the downholetool.